UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2019
or
¨

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                   to                  
Commission file number: 001-38212

Oasis Midstream Partners LP
(Exact name of registrant as specified in its charter)

Delaware
 
47-1208855
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
1001 Fannin Street, Suite 1500
Houston, Texas
 
77002
(Address of principal executive offices)
 
(Zip Code)
(281) 404-9500
(Registrant’s telephone number, including area code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   ý No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ý   No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 



Large accelerated filer
o
Accelerated filer
ý
 
 
 
 
Non-accelerated filer
o
Smaller reporting company
o
 
 
 
 
 
 
Emerging growth company
ý
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.   ý
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨  No  ý
Securities registered pursuant to Section 12(b) of the Act:
 
Title of each class
Trading symbol(s)
Name of each exchange on which registered
Common units representing limited partner interests
OMP
New York Stock Exchange
At April 30, 2019 , there were 33,795,196 units representing limited partner interests (consisting of 20,045,196 common units and 13,750,000 subordinated units) outstanding.
 
 
 
 
 




OASIS MIDSTREAM PARTNERS LP
TABLE OF CONTENTS
 
Page





PART I — FINANCIAL INFORMATION
Item 1. — Financial Statements (Unaudited)
OASIS MIDSTREAM PARTNERS LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
 
March 31, 2019
 
December 31, 2018
 
(In thousands, except unit data)
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
5,259

 
$
6,649

Accounts receivable
3,419

 
2,481

Accounts receivable - Oasis Petroleum
79,659

 
80,805

Prepaid expenses
1,366

 
1,418

Other current assets
272

 
22

Total current assets
89,975

 
91,375

Property, plant and equipment
983,632

 
933,155

Less: accumulated depreciation and amortization
(71,637
)
 
(62,730
)
Total property, plant and equipment, net
911,995

 
870,425

Operating lease right-of-use assets
3,102

 

Other assets
2,680

 
2,452

Total assets
$
1,007,752

 
$
964,252

 
 
 
 
LIABILITIES AND EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
557

 
$
2,180

Accounts payable - Oasis Petroleum
32,871

 
33,014

Accrued liabilities
63,698

 
57,657

Accrued interest payable
624

 
442

Current operating lease liabilities
2,339

 

Other current liabilities
16

 

Total current liabilities
100,105

 
93,293

Long-term debt
345,000

 
318,000

Asset retirement obligations
1,533

 
1,514

Operating lease liabilities
785

 

Other liabilities
311

 

Total liabilities
447,734

 
412,807

Commitments and contingencies (Note 9)

 

Partners’ equity
 
 
 
Limited partners
 
 
 
Common units (20,045,196 and 20,029,026 issued and outstanding at March 31, 2019 and December 31, 2018, respectively)
199,191

 
192,581

Subordinated units (13,750,000 units issued and outstanding at March 31, 2019 and December 31, 2018)
48,345

 
45,937

General Partner
238

 
112

Total partners’ equity
247,774

 
238,630

Non-controlling interests
312,244

 
312,815

Total equity
560,018

 
551,445

Total liabilities and equity
$
1,007,752

 
$
964,252

The accompanying notes are an integral part of these condensed consolidated financial statements.

1


OASIS MIDSTREAM PARTNERS LP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
 
Three Months Ended March 31,
 
2019
 
2018
 
(In thousands, except per unit data)
Revenues
 
 
 
Midstream services – Oasis Petroleum
$
74,862

 
$
57,360

Midstream services – third parties
1,127

 
563

Product sales – Oasis Petroleum
15,652

 
3,493

Product sales – third parties
10

 
5

Total revenues
91,651

 
61,421

Operating expenses
 
 
 
Costs of product sales
8,065

 
1,120

Operating and maintenance
18,850

 
15,996

Depreciation and amortization
8,929

 
6,364

General and administrative
8,720

 
6,150

Total operating expenses
44,564

 
29,630

Operating income
47,087

 
31,791

Other expense
 
 
 
Interest expense, net of capitalized interest
(3,748
)
 
(262
)
Net income
43,339

 
31,529

Less: Net income attributable to non-controlling interests
21,796

 
21,575

Net income attributable to Oasis Midstream Partners LP
21,543

 
9,954

Less: Net income attributable to General Partner
238

 

Net income attributable to limited partners
$
21,305

 
$
9,954

Earnings per limited partner unit (Note 12)
 
 
 
Common units – basic and diluted
$
0.63

 
$
0.36

Weighted average number of limited partners units outstanding (Note 12)
 
 
 
Common units – basic
20,016

 
13,750

Common units – diluted
20,033

 
13,754















The accompanying notes are an integral part of these condensed consolidated financial statements.

2



OASIS MIDSTREAM PARTNERS LP
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(UNAUDITED)
 
Partnership
 
 
 
 
 
Common Units
 
Subordinated Units
 
General Partner
 
Non-controlling Interests
 
Total
 
(In thousands)
Balance as of December 31, 2018
$
192,581

 
$
45,937

 
$
112

 
$
312,815

 
$
551,445

Contributions from non-controlling interests

 

 

 
2,532

 
2,532

Distributions to non-controlling interests

 

 

 
(21,922
)
 
(21,922
)
Distributions to unitholders
(9,020
)
 
(6,188
)
 
(112
)
 

 
(15,320
)
Equity-based compensation
119

 

 

 

 
119

Other
2,881

 
(79
)
 

 
(2,977
)
 
(175
)
Net income
12,630

 
8,675

 
238

 
21,796

 
43,339

Balance as of March 31, 2019
$
199,191

 
$
48,345

 
$
238

 
$
312,244

 
$
560,018

 
 
 
 
 
 
 
 
 
 
Balance as of December 31, 2017
$
167,401

 
$
79,173

 
$

 
$
313,446

 
$
560,020

Contributions from non-controlling interests

 

 

 
23,565

 
23,565

Distributions to non-controlling interests

 

 

 
(38,316
)
 
(38,316
)
Distributions to unitholders
(5,498
)
 
(5,493
)
 

 

 
(10,991
)
Equity-based compensation
63

 

 

 

 
63

Net income
4,977

 
4,977

 

 
21,575

 
31,529

Balance as of March 31, 2018
$
166,943

 
$
78,657

 
$

 
$
320,270

 
$
565,870




















The accompanying notes are an integral part of these condensed consolidated financial statements.

3


OASIS MIDSTREAM PARTNERS LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
Three Months Ended March 31,
 
2019
 
2018
 
(In thousands)
Cash flows from operating activities:
 
 
 
Net income
$
43,339

 
$
31,529

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
8,929

 
6,364

Equity-based compensation expenses
119

 
63

Deferred financing costs amortization
191

 
114

Working capital and other changes:
 
 
 
Change in accounts receivable
208

 
28,588

Change in prepaid expenses
52

 
31

Change in accounts payable and accrued liabilities
3,438

 
8,062

Change in other assets and liabilities, net
(226
)
 

Net cash provided by operating activities
56,050

 
74,751

Cash flows from investing activities:
 
 
 
Capital expenditures
(49,458
)
 
(76,440
)
Net cash used in investing activities
(49,458
)
 
(76,440
)
Cash flows from financing activities:
 
 
 
Capital contributions from non-controlling interests
2,532

 
15,161

Distributions to non-controlling interests
(21,922
)
 
(38,316
)
Distributions to unitholders
(15,320
)
 
(10,991
)
Deferred financing costs
(43
)
 

Proceeds from revolving credit facility
32,000

 
57,000

Principal payments on revolving credit facility
(5,000
)
 
(18,000
)
Other
(229
)
 

Net cash provided by (used in) financing activities
(7,982
)
 
4,854

Increase (decrease) in cash and cash equivalents
(1,390
)
 
3,165

Cash:
 
 
 
Beginning of period
6,649

 
883

End of period
$
5,259

 
$
4,048

Supplemental non-cash transactions:
 
 
 
Change in accrued capital expenditures
$
1,019

 
$
4,806

Change in asset retirement obligations
17

 
16

Reimbursement of capital expenditures from Oasis Petroleum

 
8,404







The accompanying notes are an integral part of these condensed consolidated financial statements.

4


OASIS MIDSTREAM PARTNERS LP
Notes to Condensed Consolidated Financial Statements (Unaudited)
1. Organization and Nature of Operations
Organization. Oasis Midstream Partners LP (the “Partnership”) is a growth-oriented, fee-based master limited partnership formed by its sponsor, Oasis Petroleum Inc. (together with its subsidiaries, “Oasis Petroleum”) to own, develop, operate and acquire a diversified portfolio of midstream assets in North America that are integral to the crude oil and natural gas operations of Oasis Petroleum and are strategically positioned to capture volumes from other producers.
Contributed businesses. The Partnership conducts its business through its ownership of development companies: Bighorn DevCo LLC (“Bighorn DevCo”), Bobcat DevCo LLC (“Bobcat DevCo”) and Beartooth DevCo LLC (“Beartooth DevCo,” and collectively with Bighorn DevCo and Bobcat DevCo, the “DevCos”). Bobcat DevCo and Beartooth DevCo are jointly-owned with Oasis Petroleum through its wholly-owned subsidiary Oasis Midstream Services LLC (“OMS”).

As of March 31, 2019 , the Partnership’s assets and ownership interests in the DevCos were as follows:
DevCos
 
Areas Served
 
Service Lines
 
Partnership Ownership
Bighorn DevCo
 
Wild Basin
South Nesson
 
Natural gas processing
Crude oil stabilization
Crude oil blending
Crude oil and natural gas liquids storage
Crude oil transportation
 
100.0%
Bobcat DevCo
 
Wild Basin
South Nesson
 
Natural gas gathering
Natural gas compression
Gas lift
Crude oil gathering
Produced and flowback water gathering
Produced and flowback water disposal
 
27.4%
Beartooth DevCo
 
Alger
Cottonwood
Hebron
Indian Hills
Red Bank
Wild Basin

 
Produced and flowback water gathering
Produced and flowback water disposal
Freshwater supply and distribution
 
70.0%
Nature of business. The Partnership generates the majority of its revenues through 15 -year, fee-based contractual arrangements with wholly-owned subsidiaries of Oasis Petroleum for midstream services. These services include (i) gas gathering, compression, processing, gas lift and natural gas liquids (“NGL”) storage services; (ii) crude oil gathering, stabilization, blending, storage and transportation services; (iii) produced and flowback water gathering and disposal services; and (iv) freshwater supply and distribution services. The revenue earned from these services is generally directly related to the volume of natural gas, crude oil, produced and flowback water and freshwater that flows through the Partnership’s systems.
The Partnership’s operations are supported by significant acreage dedications from Oasis Petroleum. In addition, the Partnership is party to a number of third party agreements across all three DevCos in which the Partnership has the right to provide its full suite of midstream services to support existing and future third party volumes.
The Partnership is not a taxable entity for United States federal income tax purposes and is not subject to income tax in any states in which the Partnership currently operates. As taxes are generally borne by its partners through the allocation of taxable income, the Partnership does not record deferred taxes related to the aggregate difference in the basis of its assets for financial and tax reporting purposes.

5


2 . Summary of Significant Accounting Policies
Basis of Presentation
The accompanying condensed consolidated financial statements of the Partnership have not been audited by the Partnership’s independent registered public accounting firm, except that the Condensed Consolidated Balance Sheet at December 31, 2018 is derived from audited financial statements. In the opinion of management, all adjustments, consisting of normal recurring adjustments necessary for fair statement of the Partnership’s financial position have been included. Management has made certain estimates and assumptions that affect reported amounts in the condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.
These interim financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements and should be read in conjunction with the Partnership’s audited consolidated financial statements and notes thereto included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018 (“ 2018 Annual Report”).
Consolidation
The Partnership’s condensed consolidated financial statements include its accounts and the accounts of the DevCos, each of which is controlled by OMP GP LLC (the “General Partner”). All intercompany balances and transactions have been eliminated upon consolidation.
Variable interest entity (“VIE”). On November 19, 2018, the Partnership completed its acquisition of an additional 15% ownership interest in Bobcat DevCo and an additional 30% ownership interest in Beartooth DevCo. The Partnership determined its acquisition of additional ownership interests in Bobcat DevCo and Beartooth DevCo was a reconsideration event in accordance with the rules of the Financial Accounting Standards Board (“FASB”) for VIEs and completed a reassessment of its prior conclusions that Bobcat DevCo and Beartooth DevCo were VIEs.
With respect to Bobcat DevCo, management determined that OMS’s equity at risk was established with non-substantive voting rights, making Bobcat DevCo a VIE under the rules of the FASB. Through its 100% ownership interest in OMP Operating LLC (“OMP Operating”), which owns a controlling interest in Bobcat DevCo, the Partnership has the authority to direct the activities that most significantly affect the economic performance of this entity and the obligation to absorb losses or the right to receive benefits that could be potentially significant. Therefore, the Partnership is considered the primary beneficiary of Bobcat DevCo and is required to consolidate this entity in its financial statements under the VIE consolidation model.
The Partnership has determined that Bighorn DevCo and Beartooth DevCo are not VIEs due to OMP Operating’s 100% and 70% ownership interest in Bighorn DevCo and Beartooth DevCo, respectively, which is proportional to its voting rights through its controlling interests. The Partnership has a controlling financial interest in Bighorn DevCo and Beartooth DevCo, through its 100% ownership interest in OMP Operating, and is required to consolidate Bighorn DevCo and Beartooth DevCo in its financial statements under the voting interest consolidation model.
Non-controlling interests. The non-controlling interests represent OMS’s retained ownership interests, as of March 31, 2019 , in Bobcat DevCo and Beartooth DevCo of 72.6% and 30% , respectively.
Significant Accounting Policies
There have been no material changes to the Partnership’s critical accounting policies and estimates from those disclosed in the 2018 Annual Report, other than as noted below.
Leases. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires lessees to recognize a right-of-use (“ROU”) asset and related liability on the balance sheet for leases with durations greater than twelve months and also requires certain quantitative and qualitative disclosures about leasing arrangements. Accounting Standards Codification 842, Leases (“ASC 842”), was subsequently amended by various Accounting Standards Updates, which provided additional implementation guidance.
The Partnership adopted the new standard as of January 1, 2019, using the required modified retrospective approach and elected the option to recognize a cumulative effect adjustment of initially applying the guidance to the opening balance of retained earnings in the period of adoption. Prior period amounts were not adjusted.
The Partnership elected the package of practical expedients under the transition guidance within the new standard, including the practical expedient to not reassess under the new standard any prior conclusions about lease identification, lease classification and initial direct costs; the use-of hindsight practical expedient; the practical expedient to not reassess the prior accounting treatment for existing or expired land easements; and the practical expedient pertaining to combining lease and non-

6


lease components for all asset classes. In addition, the Partnership elected not to apply the recognition requirements of ASC 842 to short-term leases, and as such, recognition of lease payments for short-term leases are recognized in net income on a straight line basis. See Note 8 Leases for the adoption impact and disclosures required by ASC 842.
3 . Revenue Recognition
Disaggregation of revenues
The following table presents revenues associated with contracts with customers for the periods presented:
 
Three Months Ended March 31,
 
2019
 
2018
 
(In thousands)
Service revenues
 
 
 
Crude oil and natural gas revenues
$
48,583

 
$
31,413

Produced and flowback water revenues
27,406

 
26,510

Total service revenues
75,989

 
57,923

Product revenues
 
 
 
Natural gas and NGL revenues
10,217

 

Freshwater revenues
5,445

 
3,498

Total product revenues
15,662

 
3,498

Total revenues
$
91,651

 
$
61,421

Prior period performance obligations
The Partnership records revenue when the performance obligations under the terms of its customer contracts are satisfied. The Partnership measures the satisfaction of its performance obligations using the output method based upon the volume of crude oil, natural gas or water that flows through its systems. In certain cases, the Partnership is required to estimate these volumes during a reporting period and record any differences between the estimated volumes and actual volumes in the following reporting period. Such differences have historically not been significant. For the three months ended March 31, 2019 and 2018 , revenue recognized related to performance obligations satisfied in prior reporting periods was not material.
Contract balances
Contract balances are the result of timing differences between revenue recognition, billings and cash collections. Contract liabilities are recorded for consideration received from customers related to temporary deficiency quantities under minimum volume commitments, which are expected to be made up in a future period. This consideration is subsequently recognized as revenue when the customer makes up the volumes or the deficiency makeup period expires. The Partnership does not recognize contract assets or contract liabilities under its customer contracts for which invoicing occurs once the Partnership’s performance obligations have been satisfied and payment is unconditional. No contract balances were recorded in the condensed consolidated financial statements at March 31, 2019 or December 31, 2018 .
Remaining performance obligations
The following table presents estimated revenue allocated to remaining performance obligations for contracted revenues that are unsatisfied (or partially satisfied) as of  March 31, 2019 :
 
(In thousands)
2019 (excluding the three months ended March 31, 2019)
$
20,430

2020
26,890

2021
25,638

2022
19,244

2023
12,624

Thereafter
14,642

Total
$
119,468


7


The partially and wholly unsatisfied performance obligations presented in the table above are generally limited to customer contracts which have fixed pricing and fixed volume terms and conditions, which generally include customer contracts with minimum volume commitment payment obligations.
The Partnership has elected practical expedients, pursuant to Accounting Standards Codification 606, Revenue from Contracts with Customers , to exclude from the presentation of remaining performance obligations: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services; (ii) contracts with an original expected duration of one year or less; and (iii) contracts for which the Partnership recognizes revenue under the right to invoice practical expedient.
4. Transactions with Affiliates
Revenues. The Partnership generates the majority of its revenues through 15 -year, fee-based contractual arrangements with wholly-owned subsidiaries of Oasis Petroleum for midstream services as described in Note 1 — Organization and Nature of Operations. In addition, the Partnership sells the residue gas and NGLs recovered from its gas processing plants attributable to its third party natural gas purchase agreements to Oasis Petroleum to market and sell to non-affiliated purchasers.
Expenses. Oasis Petroleum provides substantial labor and overhead support for the Partnership pursuant to a 15 -year services and secondment agreement (the “Services and Secondment Agreement”). Oasis Petroleum performs centralized corporate, general and administrative services for the Partnership, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, tax and engineering. Oasis Petroleum has also seconded to the Partnership certain of its employees to operate, construct, manage and maintain its assets. The Partnership reimburses Oasis Petroleum for direct and allocated general and administrative expenses incurred by Oasis Petroleum for the provision of these services. The expenses of executive officers and non-executive employees of Oasis Petroleum are allocated to the Partnership based on the amount of time spent managing its business and operations. The Partnership’s general and administrative expenses include $7.8 million and $5.5 million from affiliate transactions with Oasis Petroleum for the three months ended March 31, 2019 and 2018 , respectively.
2019 Capital Expenditures Arrangement. On February 22, 2019 , the Partnership entered into a memorandum of understanding (the “MOU”) with Oasis Petroleum regarding the funding of Bobcat DevCo’s capital expenditures for the 2019 calendar year (the “2019 Capital Expenditures Arrangement”). Pursuant to the Amended and Restated Limited Liability Company Agreement of Bobcat DevCo LLC, as amended (the “First A&R Bobcat LLCA”), the Partnership and Oasis Petroleum are each required to make pro-rata capital contributions to Bobcat DevCo in accordance with their respective percentage ownership interests in Bobcat DevCo.
Pursuant to the MOU, the Partnership agreed to make up to $80 million of capital expenditures to Bobcat DevCo that Oasis Petroleum would otherwise be required to contribute under the First A&R Bobcat LLCA. In connection with execution of the MOU, the Partnership and Oasis Petroleum amended the First A&R Bobcat LLCA and entered into the Second Amended and Restated Limited Liability Company Agreement of Bobcat DevCo LLC (the “Second A&R Bobcat LLCA”). The Second A&R Bobcat LLCA includes provisions applicable to the disproportionate capital contributions that the Partnership will make to Bobcat DevCo in connection with the 2019 Capital Expenditures Arrangement. Pursuant to the Second A&R Bobcat LLCA, upon the occurrence of a disproportionate capital contribution, the percentage interests of the Partnership and Oasis Petroleum in Bobcat DevCo will be adjusted to take into account the amount of the disproportionate capital contribution. During the three months ended March 31, 2019 , the Partnership made capital contributions to Bobcat DevCo pursuant to the 2019 Capital Expenditures Arrangement of $17.1 million , and the Partnership’s ownership interest in Bobcat DevCo increased from 25% as of December 31, 2018 to 27.4% as of March 31, 2019 .
5. Accrued Liabilities
Accrued liabilities consist of the following:
 
March 31, 2019
 
December 31, 2018
 
(In thousands)
Accrued capital costs
$
43,973

 
$
42,953

Accrued operating expenses
16,834

 
13,539

Other accrued liabilities
2,891

 
1,165

Total accrued liabilities
$
63,698

 
$
57,657


8


6. Property, Plant and Equipment
Property, plant and equipment consists of the following:
 
March 31, 2019
 
December 31, 2018
 
(In thousands)
Pipelines
$
425,122

 
$
395,087

Natural gas processing plants
286,252

 
278,680

Produced and flowback water facilities
95,346

 
95,119

Compressor stations
128,422

 
126,019

Other property and equipment
33,855

 
33,829

Construction in progress
14,635

 
4,422

Total property, plant and equipment
983,632

 
933,155

Less: accumulated depreciation and amortization
(71,637
)
 
(62,730
)
Total property, plant and equipment, net
$
911,995

 
$
870,425

7 . Long-Term Debt
The Partnership has a revolving credit facility with OMP Operating as borrower (the “Revolving Credit Facility”) which is available to fund working capital and to finance acquisitions and other capital expenditures of the Partnership. The aggregate amount of commitments under the Revolving Credit Facility were $400.0 million as of March 31, 2019 , and the Partnership may extend the aggregate amount of commitments under the Revolving Credit Facility from $400.0 million to $600.0 million , subject to certain conditions. The Revolving Credit Facility matures on September 25, 2022 .
At  March 31, 2019 , the Partnership had $345.0 million  of borrowings outstanding under the Revolving Credit Facility at a weighted average interest rate of 4.2% , resulting in an unused borrowing capacity of $55.0 million . The unused portion of the Revolving Credit Facility is subject to a commitment fee ranging from 0.375% to 0.500% . The fair value of the Revolving Credit Facility approximates book value since borrowings under the Revolving Credit Facility bear interest at rates which are tied to current market rates.
The Partnership was in compliance with the financial covenants under the Revolving Credit Facility at March 31, 2019 .
8 . Leases
As discussed in Note 2 Summary of Significant Accounting Policies , the Partnership adopted ASC 842 as of January 1, 2019 using the modified retrospective method, which resulted in the Partnership recognizing offsetting operating ROU assets and lease liabilities of $4.1 million . The Partnership did not have any finance leases as of the date of adoption. There was no impact to the opening equity balance as a result of the adoption of ASC 842. Prior period amounts were not adjusted and continue to be reported in accordance with previous guidance, Accounting Standards Codification 840 (“ASC 840”).
In accordance with the adoption of ASC 842, management determines whether an arrangement is a lease at its inception. The Partnership’s operating and finance leases consist primarily of equipment and land easements. The Partnership considers renewal and termination options in determining the lease term used to establish its ROU assets and lease liabilities to the extent the Partnership is reasonably certain to exercise the renewal or termination. The Partnership’s lease agreements do not contain any material residual value guarantees or material restrictive covenants.
As most of the Partnership’s leases do not provide an implicit rate, the Partnership uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future lease payments. The Partnership has determined the respective incremental borrowing rates based upon the rate of interest that would have been paid on a collateralized basis over similar tenors to that of the leases.

9


The following table sets forth the Partnership’s components of lease costs for the three months ended March 31, 2019 :
 
Three Months Ended March 31, 2019
 
(In thousands)
Operating lease costs
$
1,095

Finance lease costs:
 
Amortization of ROU assets
3

Interest on lease liabilities
2

Total lease costs
$
1,100

The operating lease costs disclosed above are included in operating and maintenance expenses on the Partnership’s Condensed Consolidated Statement of Operations. The finance lease costs for the amortization of ROU assets and the interest on lease liabilities disclosed above are included in depreciation and amortization and interest expense, net of capitalized interest, respectively, on the Partnership’s Condensed Consolidated Statements of Operations.
As of March 31, 2019 , maturities of the Partnership’s lease liabilities are as follows:
 
Operating Leases
 
Finance Leases
 
(In thousands)
2019 (excluding the three months ended March 31, 2019)
$
1,811

 
$
18

2020
1,373

 
24

2021

 
24

2022

 
24

2023

 
24

Thereafter

 
362

Total future lease payments
$
3,184

 
$
476

Less: Imputed interest
60

 
155

Present value of future lease payments
$
3,124

 
$
321

As of December 31, 2018 , future minimum annual rental commitments under non-cancelable leases under ASC 840 were as follows:
 
(In thousands)
2019
$
736

2020

2021

2022

2023

Thereafter

Total future minimum lease payments
$
736


10


Supplemental balance sheet information related to the Partnership’s leases are as follows:
 
 
Balance Sheet Classification
 
March 31, 2019
 
 
 
 
(In thousands)
Assets
 
 
 
 
Operating lease assets
 
Operating lease right-of-use assets
 
$
3,102

Finance lease assets
 
Other assets
 
376

Total lease assets
 
 
 
$
3,478

Liabilities
 
 
 
 
Current
 
 
 
 
Operating lease liabilities
 
Current operating lease liabilities
 
$
2,339

Finance lease liabilities
 
Other current liabilities
 
10

Long-term
 
 
 
 
Operating lease liabilities
 
Operating lease liabilities
 
785

Finance lease liabilities
 
Other liabilities
 
311

Total lease liabilities
 
 
 
$
3,445

Supplemental cash flow information and non-cash transactions related to the Partnership’s leases are as follows:
 
March 31, 2019
 
(In thousands)
Cash paid for amounts included in the measurement of lease liabilities
 
Operating cash flows from operating leases
$
358

Operating cash flows from finance leases
2

Financing cash flows from finance leases
55

ROU assets obtained in exchange for lease obligations
 
Operating leases
$
98

Finance leases
345

Weighted-average remaining lease term and discount rate for the Partnership’s leases are as follows:
 
As of March 31, 2019
Operating Leases
 
Weighted average remaining lease term
1.9 years

Weighted average discount rate
3.0
%
Finance Leases
 
Weighted average remaining lease term
19.8 years

Weighted average discount rate
4.3
%
9 . Commitments and Contingencies
The Partnership has various contractual obligations in the normal course of its operations. As of March 31, 2019 , there have been no material changes to the Partnership’s future commitments as disclosed in Note 10 — Commitments and Contingencies in the Partnership’s 2018 Annual Report, except as noted below.
Volume commitment agreements. As of March 31, 2019 , the Partnership had certain agreements with an aggregate requirement to either deliver or purchase a minimum quantity of approximately 22.6 million barrels of water, prior to any applicable volume credits, within specified timeframes, all of which are ten years or less. The estimable future commitments under these agreements were approximately $14.3 million as of March 31, 2019 .
Litigation. The Partnership is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. When the Partnership determines that a loss is probable of occurring and is reasonably estimable, the Partnership accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Partnership discloses contingencies where an adverse outcome may be material, or where in the judgment of management, the matter should otherwise be disclosed.

11


Mirada litigation . On March 23, 2017, Mirada filed a lawsuit against Oasis Petroleum, Oasis Petroleum America LLC (“OPNA”), and OMS, seeking monetary damages in excess of  $100.0 million , declaratory relief, attorneys’ fees and costs ( Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al. ; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). In its original lawsuit, Mirada asserts that it is a working interest owner in certain acreage owned and operated by Oasis Petroleum in Wild Basin. Specifically, Mirada asserts that Oasis Petroleum has breached certain agreements by: (1) failing to allow Mirada to participate in Oasis Petroleum’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that OPNA be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; that certain agreements apply to Oasis Petroleum and Mirada and Wild Basin with respect to this dispute; that Oasis Petroleum be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and that OPNA not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to Oasis Petroleum’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in Oasis Petroleum’s Wild Basin midstream operations, consisting of produced and flowback water disposal, crude oil gathering and gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of Oasis Petroleum’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”
On June 30, 2017, Mirada amended its original petition to add a claim that Oasis Petroleum has breached certain agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for midstream services provided by OPNA or its affiliates.
On February 2, 2018 and February 16, 2018, Mirada filed a second and third amended petition, respectively. In these filings, Mirada alleged new legal theories for being entitled to enforce the underlying contracts, and added Bighorn DevCo LLC, Bobcat DevCo LLC and Beartooth DevCo LLC as defendants, asserting that these entities were created in bad faith in an effort to avoid contractual obligations owed to Mirada. Mirada may further amend its petition from time to time to assert additional claims as well as defendants.
On March 2, 2018, Mirada filed a fourth amended petition that described Mirada’s alleged ownership and assignment of interests in assets purportedly governed by agreements at issue in the lawsuit. On August 31, 2018, Mirada filed a fifth amended petition that added the Partnership as a defendant, asserting that it was created in bad faith in an effort to avoid contractual obligations owed to Mirada.
Oasis Petroleum believes that Mirada’s claims are without merit, that Oasis Petroleum has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to Oasis Petroleum. Oasis Petroleum filed answers denying all of Mirada’s claims and intends to continue to vigorously defend against Mirada’s claims. Discovery is ongoing, and each of the parties has made a number of procedural filings and motions, and additional filings and motions can be expected over the course of the claim. Trial is scheduled for February 2020. Neither we nor Oasis Petroleum can predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to our or Oasis Petroleum’s interests, or if we or Oasis Petroleum were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on our business, results of operations, financial condition and cash flows. Such an adverse determination could materially impact Oasis Petroleum’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on its current development schedule. A determination that Mirada has a right to participate in Oasis Petroleum’s midstream operations could materially reduce the interests of Oasis Petroleum and us in our current assets and future midstream opportunities and related revenues in Wild Basin. Under the Omnibus Agreement the Partnership entered into with Oasis Petroleum in connection with the closing of the initial public offering, Oasis Petroleum agreed to indemnify the Partnership for any losses resulting from this litigation. However, the Partnership cannot guarantee that such indemnity will fully protect the Partnership from the adverse consequences of any adverse ruling.
10 . Equity-Based Compensation
The Oasis Midstream Partners LP 2017 Long Term Incentive Plan (“LTIP”) provides for the grant, at the discretion of the Board of Directors of the General Partner, of options, unit appreciation rights, restricted units, phantom units, and other unit or cash-based awards. The purpose of awards under the LTIP is to provide additional incentive compensation to individuals providing services to the Partnership and to align the economic interests of such individuals with the interests of the Partnership’s unitholders.

12


As of March 31, 2019 , the aggregate number of common units that may be issued pursuant to any and all awards under the LTIP is equal to 2,455,408 common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or expiration of awards, as provided under the LTIP. On January 1 of each calendar year following the adoption and prior to the expiration of the LTIP, the total number of common units that may be issued pursuant to the LTIP automatically increases by a number of common units equal to one percent of the number of common units outstanding on a fully diluted basis as of the close of business on the immediately preceding December 31 (calculated by adding to the number of common units outstanding, all outstanding securities convertible into common units on such date on an as converted basis).
Phantom unit awards.  In 2017, the Partnership granted under its LTIP  101,500  phantom unit awards to certain employees of Oasis Petroleum who are non-employees of the Partnership. Each phantom unit represents the right to receive a cash payment equal to the fair market value of one common unit on the day prior to the date it vests. Award recipients are also entitled to distribution equivalent rights, which represent the right to receive a cash payment equal to the value of the distributions paid on one common unit between the grant date and the vesting date. The phantom units vest in equal amounts each year over a three -year period. The phantom units are accounted for as liability-classified awards since the awards will settle in cash, and equity-based compensation cost is accounted for under the fair value method in accordance with GAAP. Under the fair value method for liability-classified awards, compensation cost is remeasured each reporting period at fair value based upon the closing price of a publicly traded common unit. Oasis Petroleum reimburses the Partnership for the cash settlement amount of these awards.
No phantom unit awards were granted under the LTIP during the three months ended March 31, 2019 . Equity-based compensation cost for phantom unit awards was $0.4 million and $0.1 million as of March 31, 2019 and December 31, 2018 , respectively, and is included on the Condensed Consolidated Balance Sheets in Accounts Receivable from Oasis Petroleum, for the portion which will be reimbursed from Oasis Petroleum, and Accrued Liabilities, for the portion which will be owed to award holders. As of  March 31, 2019 , unrecognized equity-based compensation cost for all outstanding phantom units was  $0.9 million , which is expected to be recognized over a weighted average period of  1.66  years.
Restricted unit awards.  The Partnership has granted to independent directors of the General Partner restricted unit awards under the LTIP, which vest over a  one -year period. These awards are accounted for as equity-classified awards since the awards will settle in common units upon vesting. Equity-based compensation expense is accounted for under the fair value method in accordance with GAAP. Under the fair value method for equity-classified awards, equity-based compensation expense is measured at the grant date based on the fair value of the award and is recognized over the vesting period.
During the three months ended March 31, 2019 , certain independent directors of the Partnership were granted 16,170 restricted unit awards which vest over a one-year period with a weighted-average grant date fair value of $18.57 per common unit. Equity-based compensation expense recorded for restricted unit awards was $0.1 million and $0.1 million for the three months ended March 31, 2019 and 2018 , respectively. Equity-based compensation expense is included in general and administrative expenses on the Partnership’s Condensed Consolidated Statements of Operations.
11. Partnership Equity and Distributions
Cash distributions. On  May 7, 2019 , the Board of Directors of the General Partner declared the quarterly cash distribution for the first quarter of 2019 of  $0.47  per unit. In addition, the General Partner will receive a cash distribution of $0.2 million attributable to incentive distribution rights (“IDRs”) related to the earnings for the first quarter of 2019 . These distributions will be payable on  May 29, 2019 , to unitholders of record as of  May 17, 2019 .

13


The following table details the distributions paid in respect of each period in which the distributions were earned for the following periods:
 
 
 
 
 
 
 
 
Distributions
 
 
 
 
 
 
 
 
Limited Partners
 
General Partner
Period
 
Record Date
 
Distribution Date
 
Distribution per limited partner unit
 
Common units
 
Subordinated units
 
IDRs
 
 
 
 
 
 
 
 
(In thousands)
Q1 2018
 
May 17, 2018
 
May 29, 2018
 
$
0.3925

 
$
5,406

 
$
5,397

 
$

Q2 2018
 
August 16, 2018
 
August 28, 2018
 
0.4100

 
5,649

 
5,638

 

Q3 2018
 
November 9, 2018
 
November 27, 2018
 
0.4300

 
5,925

 
5,913

 

Q4 2018
 
February 15, 2019
 
February 28, 2019
 
0.4500

 
9,020

 
6,188

 
112

Q1 2019
 
May 17, 2019
 
May 29, 2019
 
0.4700

 
9,421

 
6,463

 
238

__________________
(1)
The cash distribution for the three months ended March 31, 2019 , was determined based upon the number of units outstanding at April 30, 2019 .
Minimum quarterly distribution. The partnership agreement requires that all of the Partnership’s available cash be distributed quarterly. Under the current cash distribution policy, the Partnership intends to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.3750 per unit, or $1.50 on an annualized basis, to the extent the Partnership has sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to the General Partner and its affiliates.
Subordinated units.  Oasis Petroleum owns all of the Partnership’s subordinated units. The partnership agreement provides that, during the subordination period, the common units have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. No arrearages will accrue or be payable on the subordinated units.
When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash.
The subordination period will end on December 31 , 2020 , if each of the following tests are met:
for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date, aggregate distributions from operating surplus equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding in each quarter in each period;
for the same three consecutive, non-overlapping four-quarter periods, the “adjusted operating surplus” (as defined in the partnership agreement) equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding during each quarter on a fully diluted weighted average basis; and
there are no arrearages in payment of the minimum quarterly distribution on the common units.
Notwithstanding the foregoing, the subordination period will automatically terminate, and all of the subordinated units will convert into common units on a one-for-one basis, on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending December 31, 2018, if each of the following has occurred:
for one four-quarter period immediately preceding that date, aggregate distributions from operating surplus exceeded 150.0% of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding in each quarter in the period;
for the same four-quarter period, the “adjusted operating surplus” (as defined in the Partnership’s Amended and Restated Agreement of Limited Partnership) equaled or exceeded 150.0% of the sum of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding during each quarter on a fully diluted weighted average basis, plus the related distribution on the IDRs; and
there are no arrearages in payment of the minimum quarterly distributions on the common units.
Incentive distribution rights. The General Partner owns all of the Partnership’s IDRs, which will entitle it to increasing percentages, up to a maximum of 50.0% , of the cash the Partnership distributes in excess of $0.43125  per unit per quarter. The maximum distribution of  50.0%  does not include any distributions that Oasis Petroleum may receive on common units or subordinated units that it owns.

14


Percentage allocations of available cash from operating surplus.  For any quarter in which the Partnership has distributed cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum distribution, the Partnership will distribute any additional available cash from operating surplus for that quarter among the unitholders and the IDR holders in the following manner:
 
 
 
 
Marginal Percentage Interest in Distributions
 
 
Total Quarterly Distribution Per Unit
 
Unitholders
 
IDR Holders
Minimum Quarterly Distribution
 
up to $0.3750
 
100
%
 
%
First Target Distribution
 
above $0.3750 up to $0.4313
 
100
%
 
%
Second Target Distribution
 
above $0.4313 up to $0.4688
 
85
%
 
15
%
Third Target Distribution
 
above $0.4688 up to $0.5625
 
75
%
 
25
%
Thereafter
 
above $0.5625
 
50
%
 
50
%
12 . Earnings Per Limited Partner Unit
Earnings per limited partner unit is computed by dividing the respective limited partners’ interest in earnings attributable to the Partnership by the weighted average number of common and subordinated units outstanding. Because there is more than one class of participating securities, the Partnership uses the two-class method when calculating earnings per limited partner unit. The classes of participating securities include common units, subordinated units and IDRs.
Diluted earnings per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the LTIP, were exercised, settled or converted into common units. When it is determined that potential common units should be included in diluted net income per limited partner unit calculation, the impact is reflected by applying the treasury stock method. There are no adjustments made to net income attributable to Oasis Midstream Partners LP in the calculation of diluted earnings per unit. Diluted weighted average limited partner units outstanding includes the dilutive effect of unvested restricted unit awards (see Note 10 Equity-Based Compensation ).
The following table presents the calculation of earnings per limited partner unit under the two-class method:
 
 
Three Months Ended March 31, 2019
 
 
General Partner
 
Limited Partners
 
 
 
 
IDRs
 
Common units
 
Subordinated units
 
Total
 
 
(In thousands, except per unit data)
Net income attributable to Oasis Midstream Partners LP
 
 
 
 
 
 
 
 
Distribution declared
 
$
238

 
$
9,421

 
$
6,463

 
$
16,122

Undistributed earnings attributable to Oasis Midstream Partners LP
 

 
3,214

 
2,207

 
5,421

Net income attributable to Oasis Midstream Partners LP
 
$
238

 
$
12,635

 
$
8,670

 
$
21,543

 
 
 
 
 
 
 
 
 
Weighted average limited partners units outstanding
 
 
 
 
 
 
 
 
Basic
 
 
 
20,016

 
 
 
 
Diluted
 
 
 
20,033

 
 
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to Oasis Midstream Partners LP per limited partner unit
 
 
 
 
 
 
 
 
Basic and diluted
 
 
 
$
0.63

 
 
 
 
 
 
 
 
 
 
 
 
 
Anti-dilutive restricted units
 
 
 
9

 
 
 
 

15


 
 
Three Months Ended March 31, 2018
 
 
General Partner
 
Limited Partners
 
 
 
 
IDRs
 
Common units
 
Subordinated units
 
Total
 
 
(In thousands, except per unit data)
Net income attributable to Oasis Midstream Partners LP
 
 
 
 
 
 
 
 
Distribution declared
 
$

 
$
5,406

 
$
5,397

 
$
10,803

Excess distributions attributable to Oasis Midstream Partners LP
 

 
(429
)
 
(420
)
 
(849
)
Net income attributable to Oasis Midstream Partners LP
 
$

 
$
4,977

 
$
4,977

 
$
9,954

 
 
 
 
 
 
 
 
 
Weighted average limited partners units outstanding
 
 
 
 
 
 
 
 
Common units – basic
 
 
 
13,750

 
 
 
 
Common units – diluted
 
 
 
13,754

 
 
 
 
 
 
 
 
 
 
 
 
 
Net income attributable to Oasis Midstream Partners LP per limited partner unit
 
 
 
 
 
 
 
 
Basic
 
 
 
$
0.36

 
 
 
 
 
 
 
 
 
 
 
 
 
Anti-dilutive restricted units
 
 
 
12

 
 
 
 
13. Subsequent Events
On May 6, 2019, the Partnership entered into an amendment to its Revolving Credit Facility to (i) increase the aggregate amount of commitments from $400.0 million to $475.0 million ; (ii) provide for the ability to further increase commitments to $675.0 million ; and (iii) add a new lender to the bank group.




16


Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2018 (“ 2018 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q contains forward-looking statements. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition or provide forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” “continue” and other similar expressions are used to identify forward-looking statements.
Forward-looking statements can be affected by the assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements discussed below and detailed under Part II, Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q. Actual results may vary materially. Although forward-looking statements reflect our good faith beliefs at the time they are made, you are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and you should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include but are not limited to:
an inability of Oasis Petroleum (as defined below) or our other future customers to meet their operational and development plans on a timely basis or at all;
the execution of our business strategies;
the demand for and price of crude oil and natural gas, on an absolute basis and in comparison to the price of alternative and competing fuels;
the fees we charge, and the margins we realize, from our midstream services;
the cost of achieving organic growth in current and new markets;
our ability to make acquisitions of other midstream infrastructure assets or other assets that complement or diversify our operations;
our ability to make acquisitions of other assets on economically acceptable terms from Oasis Petroleum;
the lack of asset and geographic diversification;
the suspension, reduction or termination of our commercial agreements with Oasis Petroleum;
labor relations and government regulations;
competition and actions taken by third party producers, operators, processors and transporters;
outcomes of litigation and regulatory investigations, proceedings or inquiries;
the demand for, and the costs of developing and conducting, our midstream infrastructure services;
general economic conditions, including the risk of a prolonged economic slowdown or decline, or the risk of delay in a recovery, which can affect the long-term demand for natural gas and crude oil and related services;
the price and availability of equity and debt financing;
operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
potential effects arising from cyber threats, terrorist attacks and any consequential or other hostilities;
interruption of our operations due to social, civil or political events or unrest;
changes in environmental, safety and other laws and regulations;
the effects of accounting pronouncements issued periodically during the periods covered by forward-looking statements;
changes in our tax status;
uncertainty regarding our future operating results; and

17


certain factors discussed elsewhere in this Quarterly Report on Form 10-Q.
All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We disclaim any obligation to update or revise these statements unless required by securities law. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include, but are not limited to, commodity price volatility, inflation, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in projecting future throughput volumes, cash flow and access to capital, the timing of development expenditures and the other risks described under Part II, Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q.
Overview
We are a growth-oriented, fee-based master limited partnership formed by our sponsor, Oasis Petroleum Inc. (“Oasis Petroleum”) (NYSE: OAS), to own, develop, operate and acquire a diversified portfolio of midstream assets in North America that are integral to the crude oil and natural gas operations of Oasis Petroleum and are strategically positioned to capture volumes from other producers. Our current midstream operations are performed exclusively within the Williston Basin, one of the most prolific crude oil producing basins in North America, and we plan to expand our operations to the Delaware Basin in 2019, as described under “Highlights” below. We generate the majority of our revenues through 15-year, fixed-fee contracts pursuant to which we provide crude oil, natural gas and water-related midstream services for Oasis Petroleum. We expect to grow acquisitively through accretive, dropdown acquisitions, organically as Oasis Petroleum continues to develop its acreage and through payments of capital contributions to our DevCos that increase our percentage interest ownership in our DevCos. Additionally, we expect to grow by offering our services to third parties and through acquisitions of midstream assets from third parties.
We conduct our business through our ownership of the DevCos, two of which are jointly-owned with Oasis Petroleum, Bobcat DevCo LLC (“Bobcat DevCo”) and Beartooth DevCo LLC (“Beartooth DevCo”). As of March 31, 2019 , we own a 100% , 27.4% and 70% equity interest in our DevCos: Bighorn DevCo LLC (“Bighorn DevCo”), Bobcat DevCo and Beartooth DevCo, respectively. As of March 31, 2019 , Oasis Petroleum owns a 72.6% and 30% non-controlling equity interest in Bobcat DevCo and Beartooth DevCo, respectively. We generate the majority of our revenues through long-term, fee-based contractual arrangements, as described below, which minimize our direct exposure to commodity prices. In connection with our initial public offering, we entered into 15-year, fixed-fee contracts with wholly-owned subsidiaries of Oasis Petroleum for natural gas services (gathering, compression, processing, gas lift and natural gas liquids (“NGL”) storage services), crude oil services (gathering, stabilization, blending and storage services), produced and flowback water services (gathering and disposal services) and freshwater services (fracwater and flushwater supply and distribution services). At the same time, we became a party to the long-term, FERC-regulated transportation services agreement governing the transportation of crude oil via pipeline from the Wild Basin area to Johnson’s Corner. Our operations are supported by significant acreage dedications from Oasis Petroleum. In addition, we have increased customer diversification by entering into numerous agreements and transactions with third parties to provide our full suite of midstream services. We believe our contractual arrangements provide us with stable and predictable cash flows over the long-term. Oasis Petroleum has also granted us a right of first offer, which converts into a right of first refusal from any successor upon a change of control of Oasis Petroleum, with respect to its retained interests in two of our DevCos and any other midstream assets that Oasis Petroleum or any Oasis Petroleum successor builds with respect to its current acreage and elects to sell in the future.

18


Highlights:
Declared the quarterly cash distribution for the first quarter of 2019 of  $0.47  per unit, an approximate 5% increase from the cash distribution declared for the fourth quarter of 2018 , in line with the Partnership’s 20% annualized distribution growth target.
Net income was $43.3 million for the three months ended March 31, 2019 and net cash from operating activities was $56.1 million for the three months ended March 31, 2019 .
Adjusted EBITDA was $56.1 million for the three months ended March 31, 2019 and net Adjusted EBITDA to the Partnership was $31.5 million for the three months ended March 31, 2019 . See “Non-GAAP Financial Measures” below.
Distributable Cash Flow was $26.2 million for the three months ended March 31, 2019 , resulting in distribution coverage of 1.6 x. See “Non-GAAP Financial Measures” below.
Increased Bighorn DevCo natural gas volumes by 71% from the fourth quarter of 2018, up to 193 million standard cubic feet per day (“MMscfpd”) in the first quarter of 2019 , and increased Bobcat DevCo natural gas volumes by 45% from the fourth quarter of 2018, up to 241 MMscfpd in the first quarter of 2019 . Third party natural gas volumes represented over 15% of the volumes processed in Bighorn DevCo in the first quarter of 2019 .
The Boards of Directors of Oasis Petroleum and OMP GP LLC, our general partner (the “General Partner”), have approved entering into acreage dedications and midstream services arrangements in the Delaware Basin on terms similar to the existing commercial arrangements between us and Oasis Petroleum in the Williston Basin. We anticipate that Oasis Petroleum will dedicate to us certain acreage in and around its position in the Delaware Basin which is currently undedicated for crude oil and produced water infrastructure development. We will form a new wholly-owned DevCo called Panther DevCo LLC, and we expect to spend an additional $53 million to $57 million in 2019 on such infrastructure build-out, including purchases from Oasis Petroleum for existing midstream assets in the Delaware Basin.

19


The following table summarizes the gross throughput volumes, operating income, depreciation and amortization and capital expenditures (“CapEx”) of each of our DevCos for the three months ended March 31, 2019 and 2018 .
 
Three Months Ended March 31,
 
2019
 
2018
 
(In thousands, except throughput volumes)
Bighorn DevCo
 
 
 
Crude oil services volumes (Mbopd)
50.6

 
41.5

Natural gas services volumes (MMscfpd)
193.0

 
98.0

Operating income
$
10,564

 
$
5,014

Depreciation and amortization
3,735

 
2,533

Capital expenditures
6,955

 
41,445

Bobcat DevCo
 
 
 
Crude oil services volumes (Mbopd)
42.5

 
36.3

Natural gas services volumes (MMscfpd)
241.0

 
140.4

Water services volumes (Mbowpd)
51.2

 
43.0

Operating income
$
23,914

 
$
16,915

Depreciation and amortization
2,919

 
2,086

Capital expenditures
34,533

 
27,763

Beartooth DevCo
 
 
 
Water services volumes (Mbowpd)
133.1

 
108.4

Operating income
$
13,509

 
$
10,585

Depreciation and amortization
2,275

 
1,745

Capital expenditures
8,955

 
11,203

Oasis Midstream Partners LP
 
 
 
DevCo operating income
$
47,987

 
$
32,514

Public company expenses
900

 
723

Partnership operating income
47,087

 
31,791

Depreciation and amortization
8,929

 
6,364

Equity-based compensation expense
119

 
63

Capitalized interest
35

 
835

Total CapEx
50,478

 
81,246

Maintenance CapEx
4,390

 
2,379

Expansion CapEx
46,088

 
78,867

How We Evaluate Our Operations
We use a variety of financial and operating metrics to analyze our operating results and profitability. These metrics are significant factors in assessing our operating results and profitability and include: (i) throughput volumes, (ii) Adjusted EBITDA, (iii) Distributable Cash Flow, (iv) capital expenditures, (v) operating expenses and (vi) general and administrative expenses. Adjusted EBITDA and Distributable Cash Flow are supplemental non-GAAP financial measures. For a definition of these non-GAAP financial measures and a reconciliation to the most directly comparable GAAP measure, see “Non-GAAP Financial Measures” below.
Throughput Volumes
The amount of revenue we generate primarily depends on the volumes of crude oil, natural gas and water for which we provide midstream services. By connecting new producing wells to our gathering systems and by increasing capacity on our systems, we are able to increase volumes. Additionally, by performing routine maintenance and monitoring of our infrastructure, we are able to minimize service interruptions on our gathering systems.
Under our commercial agreements with Oasis Petroleum and its wholly-owned subsidiaries, we provide (i) natural gas gathering, compression, processing, gas lift and NGL storage services; (ii) crude oil gathering, stabilization, blending and storage services; (iii) produced and flowback water gathering and disposal services; and (iv) freshwater supply and distribution

20


services. In addition, we are party to a FERC-regulated crude oil transportation services agreement, which provides for crude oil transportation from the Wild Basin operating area to Johnson’s Corner that has up to 75,000 barrels per day of operating capacity and firm capacity for committed shippers.
Throughput volumes are affected by changes in the supply of and demand for crude oil and natural gas in the markets served directly or indirectly by our assets. Because the production rate of a well declines over time, we must continually obtain new supplies of crude oil, natural gas and produced and flowback water to maintain or increase the throughput volumes on our midstream systems. Because freshwater supply and distribution services are largely dependent on well completion activities, our ability to provide freshwater supply and distribution services is contingent on our customers drilling and completing new wells in and around our freshwater infrastructure. Our customers’ willingness to engage in new development activity is determined by a number of factors, the most important of which are the prevailing and projected prices of crude oil and natural gas, the cost to drill, complete and operate a well, expected well performance, the availability and cost of capital and environmental and government regulations. We generally expect the level of development activity to positively correlate with long-term trends in commodity prices and similarly, production levels to positively correlate with development activity.
Our ability to maintain or increase existing throughput volumes and obtain new supplies of crude oil, natural gas and produced, flowback and freshwater are impacted by:
successful development activity by Oasis Petroleum on our dedicated acreage and our ability to fund the capital costs required to connect our infrastructure assets to new wells;
our ability to utilize the remaining uncommitted capacity on, or add additional capacity to, our infrastructure assets;
the level of workovers and recompletions of wells on existing pad sites to which our infrastructure assets are connected;
our ability to identify and execute organic expansion projects to capture incremental volumes from Oasis Petroleum and third parties;
our ability to compete for volumes from successful new wells in the areas in which we operate outside of our dedicated acreage;
our ability to provide crude oil, natural gas and water-related midstream services with respect to volumes produced on acreage that has been released from commitments with our competitors; and
our ability to obtain financing for acquiring incremental assets in dropdown transactions from Oasis Petroleum.
We actively monitor producer activity in the areas served by our infrastructure assets to identify opportunities to connect new wells to our gathering systems.
Adjusted EBITDA and Distributable Cash Flow
We define Adjusted EBITDA as earnings before interest expense (net of capitalized interest), income taxes, depreciation, amortization, impairment, equity-based compensation expenses and other similar non-cash adjustments. We define Adjusted EBITDA attributable to the Partnership as Adjusted EBITDA less Adjusted EBITDA attributable to Oasis Petroleum’s retained interests in two of our DevCos, Bobcat DevCo and Beartooth DevCo. We define Distributable Cash Flow as Adjusted EBITDA attributable to the Partnership less cash paid for interest and maintenance capital expenditures attributable to the Partnership.
Adjusted EBITDA and Distributable Cash Flow are not presentations made in accordance with GAAP. These non-GAAP supplemental financial measures may be used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, to assess:
our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing methods;
the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;
our ability to incur and service debt and fund capital expenditures; and
the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
We believe that the presentation of Adjusted EBITDA and Distributable Cash Flow provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and Distributable Cash Flow are net income and net cash provided by operating activities, respectively. Adjusted EBITDA and Distributable Cash Flow should not be considered as alternatives to GAAP net income, income from operations, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and Distributable Cash Flow have important limitations as analytical tools because they exclude some, but not all, items that affect net income and net cash provided by operating activities. Adjusted EBITDA or Distributable Cash

21


Flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and Distributable Cash Flow may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For a further discussion of Adjusted EBITDA and Distributable Cash Flow and reconciliations of Adjusted EBITDA and Distributable Cash Flow to net income and net cash provided by operating activities, see “Non-GAAP Financial Measures” below.
Capital Expenditures
The midstream energy business is capital intensive; thus, our operations require capital investments to maintain, expand, upgrade or enhance our existing operations. Our capital requirements are categorized as either:
Maintenance capital expenditures, which are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long-term, system operating capacity, operating income or revenue. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to maintain equipment reliability, integrity and safety and to comply with environmental laws and regulations. In addition, we designate a portion of our capital expenditures to connect new wells to maintain gathering throughput as maintenance capital expenditures to the extent such capital expenditures are necessary to maintain, over the long term, system operating capacity, operating income or revenue. Cash expenditures made solely for investment purposes will not be considered maintenance capital expenditures; or
Expansion capital expenditures , which are cash expenditures to acquire additional interests in our midstream assets and to construct new midstream infrastructure and those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system operating capacity, operating income or revenue. Examples of expansion capital expenditures include the acquisition of additional interests in our DevCos and the construction, development or acquisition of additional midstream assets, in each case, to the extent such capital expenditures are expected to increase, over the long term, system operating capacity, operating income or revenue. In the future, if we make acquisitions that increase system operating capacity, operating income or revenue, the associated capital expenditures may also be considered expansion capital expenditures.
Operating Expenses
We seek to maximize the profitability of our operations by effectively managing operating expenses, including operating and maintenance expenses and costs of product sales. Operating expenses do not extend the useful life of property, plant and equipment. Operating and maintenance expenses are primarily comprised of direct labor, utility costs, insurance premiums, third party service provider costs, related property taxes and other non-income taxes, expenditures to repair, refurbish and replace facilities and to maintain equipment reliability, integrity and safety. Costs of product sales are primarily comprised of freshwater purchases, natural gas purchases under arrangements with third parties, and certain related operating costs.
These operating expenses fluctuate from period to period depending on the mix of activities performed during any specified period and the timing of these expenses. Because many of these expenses are fixed in nature, we expect to lower operating expenses as a percentage of revenue as we add incremental volumes onto our gathering systems. We will seek to manage our operating expenditures by scheduling periodic maintenance on our assets in order to minimize significant variability in these expenditures and their impact on our cash flow.
General and Administrative Expenses
We are party to a 15-year services and secondment agreement with Oasis Petroleum (the “Services and Secondment Agreement”), pursuant to which Oasis Petroleum performs certain general and administrative (“G&A”) services on behalf of the Partnership, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, tax and engineering (collectively “G&A services”). In addition, Oasis Petroleum has seconded to us certain of its employees to operate, construct, manage and maintain our assets. The Services and Secondment Agreement requires us to reimburse Oasis Petroleum for direct G&A expenses incurred for the provision of these services. Oasis Petroleum charges us a combination of direct and indirect allocated charges for G&A services using certain estimates and assumptions of the expenses attributable to our operations. Management believes these estimates and assumptions are reasonable. In addition, we incur costs as a publicly traded partnership which consist primarily of accounting and audit fees, legal fees, board and director expenses, and equity-based compensation expenses.

22


Results of Operations
Revenues
Our revenues are primarily generated from charging fees to our customers for the midstream services we provide, and we categorize our revenues as either service revenues or product sales (see Note 3 to our condensed consolidated financial statements).
Service revenues. We categorize the following services we provide Oasis Petroleum as service revenues: (i) natural gas gathering, compression, processing, gas lift and NGL storage services; (ii) crude oil gathering, stabilization, blending, storage and transportation services; and (iii) produced and flowback water gathering and disposal services. We also categorize as service revenues produced and flowback water gathering and disposal services we provide to third parties.
Product sales. We record product sales for the delivery of residue gas and NGLs to Oasis Petroleum, which we generate from natural gas purchase arrangements with third parties. We also record product sales for the supply and distribution of freshwater to both Oasis Petroleum and third parties.
The following table summarizes our revenues for the periods presented:
 
Three Months Ended March 31,
 
2019
 
2018
 
Change
Operating results (in thousands):
 
 
 
 
 
Revenues
 
 
 
 
 
Midstream services – Oasis Petroleum
$
74,862

 
$
57,360

 
$
17,502

Midstream services – third parties
1,127

 
563

 
564

Product sales – Oasis Petroleum
15,652

 
3,493

 
12,159

Product sales – third parties
10

 
5

 
5

Total revenues
$
91,651

 
$
61,421

 
$
30,230

Three months ended March 31, 2019 as compared to three months ended March 31, 2018
Total revenues increased $30.2 million to $91.7 million during the  three months ended March 31, 2019 , as compared to the three months ended March 31, 2018 . This increase was driven by a $18.1 million increase in service revenues and $12.1 million increase in product sales. The increase in service revenues was primarily due to a $15.8 million increase in natural gas service revenues due to higher natural gas service volumes as a result of the start-up of our second natural gas processing plant in Wild Basin during the fourth quarter of 2018 . In addition, there was a $1.3 million increase in crude oil service revenues and $0.9 million increase in produced and flowback water service revenues, primarily as a result of increased production volumes from Oasis Petroleum. The increase in product sales was driven by a $10.2 million increase in natural gas product sales as a result of the commencement of natural gas purchase arrangements with third parties during the fourth quarter of 2018 , coupled with a $1.9 million increase related to higher freshwater product sales to Oasis Petroleum as a result of increased completion activity.

23


Expenses and other income
The following table summarizes our operating expenses and other income and expenses for the periods presented:
 
Three Months Ended March 31,
 
2019
 
2018
 
Change
 
(In thousands)
Operating expenses
 
 
 
 
 
Costs of product sales
$
8,065

 
$
1,120

 
$
6,945

Operating and maintenance
18,850

 
15,996

 
2,854

Depreciation and amortization
8,929

 
6,364

 
2,565

General and administrative
8,720

 
6,150

 
2,570

Total operating expenses
44,564

 
29,630

 
14,934

Operating income
47,087

 
31,791

 
15,296

Other expense
 
 
 
 

Interest expense, net of capitalized interest
(3,748
)
 
(262
)
 
(3,486
)
Net income
43,339

 
31,529

 
11,810

Less: Net income attributable to non-controlling interests
21,796

 
21,575

 
221

Net income attributable to Oasis Midstream Partners LP
21,543

 
9,954

 
11,589

Less: Net income attributable to General Partner
238

 

 
238

Net income attributable to limited partners
$
21,305

 
$
9,954

 
$
11,351

Three months ended March 31, 2019 as compared to three months ended March 31, 2018
Costs of product sales . The $6.9 million increase for the three months ended March 31, 2019 , as compared to the three months ended March 31, 2018 , was primarily due to a $6.1 million increase in natural gas purchases from third parties, which commenced during the fourth quarter of 2018 , coupled with a $0.8 million increase in freshwater costs of product sales as a result of an increase in freshwater operating costs due to higher completion activity.
Operating and maintenance. Operating and maintenance expenses increased $2.9 million to $18.9 million  for the three months ended March 31, 2019 , as compared to the three months ended March 31, 2018 . The increase was primarily driven by a $3.7 million increase related to higher natural gas operating and maintenance expenses as a result of the start-up of our second natural gas processing plant in Wild Basin during the fourth quarter of 2018 . In addition, there was a $0.7 million increase in crude oil operating and maintenance expenses due to higher crude oil service volumes, partially offset by a $1.6 million decrease related to produced and flowback water operating and maintenance expenses.
Depreciation and amortization. Depreciation and amortization expense increased $2.6 million to $8.9 million for the three months ended March 31, 2019 , as compared to the three months ended March 31, 2018 , primarily as a result of additional assets placed into service.
G&A expenses. G&A expenses increased $2.6 million to $8.7 million for the three months ended March 31, 2019 , as compared to the three months ended March 31, 2018 . The increase was primarily a result of an increase in allocated charges from Oasis Petroleum for G&A services as a result of organizational growth.
Interest expense, net of capitalized interest. Interest expense, net of capitalized interest, increased $3.5 million to $3.7 million for the three months ended March 31, 2019 , as compared to the three months ended March 31, 2018 . The increase was primarily due to higher outstanding borrowings under our Revolving Credit Facility, coupled with lower capitalized interest costs due to lower construction in progress as a result of our second natural gas processing plant in Wild Basin being placed in-service during the fourth quarter of 2018.

24


Liquidity and Capital Resources
Our primary sources of liquidity are cash flows generated from operations and borrowings under our Revolving Credit Facility. We believe cash generated from these sources will be sufficient to meet our short-term working capital needs, long-term capital expenditure requirements and quarterly cash distributions. As a result, we expect to fund future expansion capital expenditures and acquisitions primarily through a combination of borrowings under our Revolving Credit Facility and, if necessary, the issuance of additional equity or debt securities. Our primary uses of cash have been for capital expenditures towards our midstream infrastructure, the acquisition of additional ownership interests in two of our DevCos, Bobcat DevCo and Beartooth DevCo, payment of operating costs, payment of general and administrative costs and interest payments on outstanding debt. We expect our future cash requirements relating to working capital, maintenance capital expenditures and quarterly cash distributions to our unitholders will be funded from cash flows internally generated from our operations.
Our cash flows for the three months ended March 31, 2019 and 2018 are presented below:
 
Three Months Ended March 31,
 
2019
 
2018
 
(In thousands)
Net cash provided by operating activities
$
56,050

 
$
74,751

Net cash used in investing activities
(49,458
)
 
(76,440
)
Net cash provided by (used in) financing activities
(7,982
)
 
4,854

Increase (decrease) in cash and cash equivalents
$
(1,390
)
 
$
3,165

Cash flows provided by operating activities
Net cash provided by operating activities was $56.1 million and $74.8 million for the three months ended March 31, 2019 and 2018 , respectively. The decrease in cash flows from operating activities for the three months ended March 31, 2019 , as compared to 2018 , was primarily due to lower changes in working capital.
Working capital. Our working capital fluctuates primarily as a result of changes in service volumes flowing through our systems and accrued spending related to our midstream infrastructure. As of March 31, 2019 , we had a working capital deficit of approximately $10.1 million . We believe we have adequate liquidity to meet our working capital requirements. As of March 31, 2019 , we had $60.3 million of liquidity available, including $5.3 million in cash and cash equivalents and $55.0 million in unused borrowing capacity on our Revolving Credit Facility.
Cash flows used in investing activities
Net cash used in investing activities was $49.5 million and $76.4 million for the three months ended March 31, 2019 and 2018 , respectively. The decrease in net cash used in investing activities for the three months ended March 31, 2019 , as compared to 2018 , was primarily attributable to lower capital spending on our midstream infrastructure in Wild Basin, including our second natural gas processing plant, which was placed in-service during the fourth quarter of 2018.
2019 Capital Expenditures Arrangement. On February 22, 2019 , the Partnership entered into a memorandum of understanding (the “MOU”) with Oasis Petroleum regarding the funding of Bobcat DevCo’s capital expenditures for the 2019 calendar year (the “2019 Capital Expenditures Arrangement”). Pursuant to the Amended and Restated Limited Liability Company Agreement of Bobcat DevCo LLC, as amended (the “First A&R Bobcat LLCA”), the Partnership and Oasis Petroleum are each required to make pro-rata capital contributions to Bobcat DevCo in accordance with their respective percentage ownership interests in Bobcat DevCo.
Pursuant to the MOU, the Partnership agreed to make up to $80.0 million of capital expenditures to Bobcat DevCo that Oasis Petroleum would otherwise be required to contribute under the First A&R Bobcat LLCA. In connection with execution of the MOU, the Partnership and Oasis Petroleum amended the First A&R Bobcat LLCA and entered into the Second Amended and Restated Limited Liability Company Agreement of Bobcat DevCo LLC (the “Second A&R Bobcat LLCA”). The Second A&R Bobcat LLCA includes provisions applicable to the disproportionate capital contributions that the Partnership will make to Bobcat DevCo in connection with the 2019 Capital Expenditures Arrangement. Pursuant to the Second A&R Bobcat LLCA, upon the occurrence of a disproportionate capital contribution, the Partnership’s percentage interest and Oasis Petroleum’s percentage interest in Bobcat DevCo will be adjusted to take into account the amount of the disproportionate capital contribution. During the three months ended March 31, 2019 , the Partnership made capital contributions to Bobcat DevCo pursuant to the 2019 Capital Expenditures Arrangement of $17.1 million , and the Partnership’s ownership interest in Bobcat DevCo increased from 25% as of December 31, 2018 to 27.4% as of March 31, 2019 .

25


Capital expenditures. During the three months ended March 31, 2019 , gross capital expenditures were $50.5 million . Our capital expenditures are summarized in the following table for the three months ended March 31, 2019 :
 
Three Months Ended March 31, 2019
 
(In thousands)
Capital expenditures
Gross
 
Net
Maintenance CapEx
$
4,390

 
$
1,667

Expansion CapEx (1)
46,088

 
43,557

Total CapEx  (2)
$
50,478

 
$
45,224

__________________
(1)
Includes capitalized interest of $35,000 for the three months ended March 31, 2019 .
(2)
Capital expenditures reflected in the tables above differ from capital expenditures shown in the statement of cash flows in our condensed consolidated financial statements because amounts reflected in the tables above include changes in accrued capital expenditures from the previous reporting period, while amounts presented in the statements of cash flows are presented on a cash basis.
Our capital expenditures by DevCo are summarized in the following table for the three months ended March 31, 2019 :
 
 
 
Three Months Ended March 31, 2019
 
 
 
(In thousands)
DevCo
 
Partnership Ownership (2)
Gross
 
Net
Bighorn DevCo
 
100.0%
$
6,955

 
$
6,955

Bobcat DevCo
 
27.4%
34,533

 
31,965

Beartooth DevCo
 
70.0%
8,955

 
6,269

OMP Operating LLC
 
100.0%
35

 
35

Total CapEx  (1)
 
 
$
50,478

 
$
45,224

__________________
(1)
Capital expenditures reflected in the tables above differ from capital expenditures shown in the statement of cash flows in our condensed consolidated financial statements because amounts reflected in the tables above include changes in accrued capital expenditures from the previous reporting period, while amounts presented in the statements of cash flows are presented on a cash basis.
(2)
Represents the Partnership’s ownership in each DevCo as of March 31, 2019 .
Cash flows used in financing activities
For the three months ended March 31, 2019 , net cash used in financing activities was $8.0 million . For the three months ended March 31, 2018 , net cash provided by financing activities was $4.9 million . Net cash used in financing activities for the three months ended March 31, 2019 was primarily attributable to distributions to non-controlling interests of $21.9 million and distributions to unitholders of $15.3 million , partially offset by net borrowings on the Revolving Credit Facility of $27.0 million and capital contributions from non-controlling interests of $2.5 million . The primary sources of net cash provided by financing activities for the three months ended March 31, 2018 , were net borrowings on the Revolving Credit Facility of $39.0 million , capital contributions from non-controlling interests of $15.2 million , partially offset by distributions to non-controlling interests of $38.3 million and distributions to unitholders of $11.0 million .
Revolving credit facility. The Revolving Credit Facility had an aggregate amount of commitments of $400.0 million as of March 31, 2019 . The Revolving Credit Facility is available to fund working capital and to finance acquisitions and other capital expenditures. At  March 31, 2019 $345.0 million  of borrowings were outstanding under the Revolving Credit Facility, and the weighted average interest rate on borrowings under the Revolving Credit Facility was 4.2% . On May 6, 2019, the Partnership entered into an amendment to its Revolving Credit Facility to (i) increase the aggregate amount of commitments from $400.0 million to $475.0 million ; (ii) provide for the ability to further increase commitments to $675.0 million ; and (iii) add a new lender to the bank group.
The Revolving Credit Facility also requires the Partnership to maintain the following financial covenants as of the end of each fiscal quarter:
Consolidated Total Leverage Ratio: Prior to the date on which one or more of the credit parties have issued an aggregate principal amount of at least $150.0 million of senior notes (as permitted under the Revolving Credit Facility) (such date the

26


“Covenant Changeover Date”) and commencing with the fiscal quarter ended December 31, 2017, the Partnership and OMP Operating’s ratio of Total Debt to EBITDA (each as defined in the credit agreement) on a quarterly basis may not exceed 4.50 to 1.00 (or during an acquisition period (as defined in the credit agreement), 5.00 to 1.00). On a quarterly basis following the Covenant Changeover Date, the Partnership and OMP Operating’s ratio of Total Debt to EBITDA may not exceed 5.25 to 1.00.
Consolidated Senior Secured Leverage Ratio: On a quarterly basis, commencing with the date the Covenant Changeover Date occurs, the Partnership and OMP Operating’s ratio of Consolidated Senior Secured Funded Debt to EBITDA (each as defined in the credit agreement) may not exceed 3.75 to 1.00.
Consolidated Interest Coverage Ratio: On a quarterly basis prior to the Covenant Changeover Date and commencing with the fiscal quarter ended December 31, 2017, the Partnership and OMP Operating’s ratio of EBITDA to Consolidated Interest Expense (each as defined in the credit agreement) may not be less than 3.00 to 1.00 and on a quarterly basis following the Covenant Changeover Date, the Partnership and OMP Operating’s ratio of EBITDA to Consolidated Interest Expense may not be less than 2.50 to 1.00.
The Partnership was in compliance with the financial covenants under the Revolving Credit Facility at March 31, 2019 .
Cash Distributions
Our partnership agreement requires that all of the Partnership’s available cash be distributed quarterly. Under the current cash distribution policy, the Partnership intends to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of  $0.3750  per unit, or  $1.50  on an annualized basis, to the extent the Partnership has sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to the General Partner and its affiliates. 
On  May 7, 2019 , the Board of Directors of the General Partner declared the quarterly distribution for the first quarter of 2019 of  $0.47  per unit. In addition, the General Partner will receive a cash distribution of $0.2 million attributable to IDRs related to earnings for the first quarter of 2019 . These distributions will be payable on  May 29, 2019  to unitholders of record as of  May 17, 2019 .
Non-GAAP Financial Measures
Cash Interest, Adjusted EBITDA and Distributable Cash Flow are supplemental non-GAAP financial measures that are used by management and external users of the Partnership’s financial statements, such as industry analysts, investors, lenders and rating agencies. These non-GAAP financial measures should not be considered in isolation or as a substitute for interest expense, net income (loss), operating income (loss), net cash provided by (used in) operating activities or any other measures prepared under GAAP. Because Cash Interest, Adjusted EBITDA and Distributable Cash Flow exclude some but not all items that affect interest expense, net income and net cash provided by operating activities and may vary among companies, the amounts presented may not be comparable to similar metrics of other companies.
Cash Interest
Cash Interest is defined as interest expense plus capitalized interest less amortization of deferred financing costs included in interest expense. Cash Interest is not a measure of interest expense as determined by GAAP. Management believes that the presentation of Cash Interest provides useful additional information to investors and analysts for assessing the interest charges incurred on the Partnership’s debt, excluding non-cash amortization, and the Partnership’s ability to maintain compliance with its debt covenants.

27


The following table presents a reconciliation of the GAAP financial measure of interest expense, net of capitalized interest, to the non-GAAP financial measure of Cash Interest for the periods presented:
 
Three Months Ended March 31,
 
2019
 
2018
 
(In thousands)
Interest expense, net of capitalized interest
$
3,748

 
$
262

Capitalized interest
35

 
835

Amortization of deferred financing costs
(191
)
 
(116
)
Cash Interest
3,592

 
981

Less: Cash Interest attributable to non-controlling interests (1)
(2
)
 

Cash Interest attributable to Oasis Midstream Partners LP
$
3,590

 
$
981

__________________
(1) Amount represents Cash Interest attributable to non-controlling interests associated with finance leases.
Adjusted EBITDA
Adjusted EBITDA is defined as earnings before interest expense (net of capitalized interest), income taxes, depreciation, amortization, equity-based compensation expenses and other similar non-cash adjustments. Adjusted EBITDA attributable to Oasis Midstream Partners LP is defined as Adjusted EBITDA less Adjusted EBITDA attributable to Oasis Petroleum’s retained interests in two of the Partnership’s DevCos, Bobcat DevCo and Beartooth DevCo. Adjusted EBITDA should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Management believes that the presentation of Adjusted EBITDA provides information useful to investors and analysts for assessing the Partnership’s results of operations, financial performance and the Partnership’s ability to generate cash from its business operations without regard to the Partnership’s financing methods or capital structure, coupled with the Partnership’s ability to maintain compliance with its debt covenants. The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities, respectively.
Distributable Cash Flow
Distributable Cash Flow is defined as Adjusted EBITDA attributable to Oasis Midstream Partners LP less Cash Interest attributable to Oasis Midstream Partners LP and maintenance capital expenditures attributable to Oasis Midstream Partners LP. Distributable Cash Flow should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Management believes that the presentation of Distributable Cash Flow provides information useful to investors and analysts for assessing the Partnership’s results of operations, financial performance and the Partnership’s ability to generate cash from its business operations without regard to the Partnership’s financing methods or capital structure, coupled with the Partnership’s ability to make distributions to its unitholders. The GAAP measures most directly comparable to Distributable Cash Flow are net income and net cash provided by operating activities, respectively.

28


The following table presents reconciliations of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow for the periods presented:
 
Three Months Ended March 31,
 
2019
 
2018
 
(In thousands)
Net income
$
43,339

 
$
31,529

Depreciation and amortization
8,929

 
6,364

Equity-based compensation expense
119

 
63

Interest expense, net of capitalized interest
3,748

 
262

Adjusted EBITDA
56,135

 
38,218

Less: Adjusted EBITDA attributable to non-controlling interests
24,647

 
24,496

Adjusted EBITDA attributable to Oasis Midstream Partners LP
31,488

 
13,722

Less:
 
 
 
Cash Interest attributable to Oasis Midstream Partners LP
3,590

 
981

Maintenance capital expenditures attributable to Oasis Midstream Partners LP
1,667

 
796

Distributable Cash Flow attributable to Oasis Midstream Partners LP
$
26,231

 
$
11,945

 
 
 
 
Net cash provided by operating activities
$
56,050

 
$
74,751

Interest expense, net of capitalized interest
3,748

 
262

Changes in working capital
(3,472
)
 
(36,681
)
Other non-cash adjustments
(191
)
 
(114
)
Adjusted EBITDA
56,135

 
38,218

Less: Adjusted EBITDA attributable to non-controlling interests
24,647

 
24,496

Adjusted EBITDA attributable to Oasis Midstream Partners LP
31,488

 
13,722

Less:
 
 
 
Cash Interest attributable to Oasis Midstream Partners LP
3,590

 
981

Maintenance capital expenditures attributable to Oasis Midstream Partners LP
1,667

 
796

Distributable Cash Flow attributable to Oasis Midstream Partners LP
$
26,231

 
$
11,945


29


Off-Balance Sheet Arrangements
We have not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities.
Critical Accounting Policies and Estimates
There have been no material changes to our critical accounting policies and estimates from those disclosed in our 2018 Annual Report other than as disclosed in Note 2 to our unaudited condensed consolidated financial statements.
Item 3. — Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.
Concentration of customer credit risk. We are dependent on Oasis Petroleum as our most significant customer, and we expect to derive a substantial majority of our revenues from Oasis Petroleum for the foreseeable future. As a result, any event, whether in our dedicated areas or otherwise, that adversely affects Oasis Petroleum’s production, drilling schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows may adversely affect our revenues and cash available for distribution. Further, we are subject to the risk of non-payment or non-performance by Oasis Petroleum. We cannot predict the extent to which Oasis Petroleum’s business would be impacted if conditions in the energy industry were to deteriorate, nor can we estimate the impact such conditions would have on Oasis Petroleum’s ability to execute its drilling and development program or to perform under our agreements. Any material non-payment or non-performance by Oasis Petroleum could reduce our ability to make distributions to our unitholders. We did not experience any significant defaults on accounts receivable for the three months ended March 31, 2019 .
Commodity price risk . We have limited direct exposure to risks associated with fluctuating commodity prices due to the nature of our business and our long-term, fixed-fee arrangements with Oasis Petroleum. However, to the extent that our future contractual arrangements with Oasis Petroleum or third parties do not provide for fixed-fee structures, we may become subject to commodity price risk. Additionally, as a substantial portion of our revenues are derived from Oasis Petroleum, we will be indirectly subject to risks associated with fluctuating commodity prices to the extent that lower commodity prices adversely affect Oasis Petroleum’s production, drilling schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows.
Interest rate risk . We have a Revolving Credit Facility which provides for an aggregate commitment amount of $400.0 million as of March 31, 2019 . At March 31, 2019 , we had $345.0 million of borrowings under the Revolving Credit Facility. Borrowings under the Revolving Credit Facility bear interest at a rate per annum equal to the applicable margin (as described below) plus (i) with respect to Eurodollar Loans, the Adjusted LIBO Rate (as defined in the credit agreement) or (ii) with respect to ABR Loans, the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 1/2 of 1.00% or (c) the Adjusted LIBO Rate for a one-month interest period on such day plus 1.00% (each as defined in the credit agreement). The applicable margin for borrowings under the Revolving Credit Facility is based on the Partnership’s most recently tested consolidated total leverage ratio and varies from (a) in the case of Eurodollar Loans, 1.75% to 2.75%, and (b) in the case of ABR Loans or swingline loans, 0.75% to 1.75%. The unused portion of the Revolving Credit Facility is subject to a commitment fee ranging from 0.375% to 0.500%.
At  March 31, 2019 , the outstanding borrowings under our Revolving Credit Facility bore interest at LIBOR plus a 1.75% margin. We do not currently, but may in the future, utilize interest rate derivatives to mitigate interest rate exposure in efforts to reduce interest rate expense related to debt issued under our Revolving Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

30


Item 4. — Controls and Procedures
Evaluation of disclosure controls and procedures. As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2019 . Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effective at March 31, 2019 .
Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the three months ended March 31, 2019 , that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


31


PART II — OTHER INFORMATION
Item 1. — Legal Proceedings
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, except as disclosed below, we are not currently subject to any potentially material litigation. We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure our unitholders that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
Mirada litigation. On March 23, 2017, Mirada filed a lawsuit against Oasis Petroleum, OPNA, and OMS, seeking monetary damages in excess of $100.0 million , declaratory relief, attorneys’ fees and costs ( Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al .; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). In its original lawsuit, Mirada asserts that it is a working interest owner in certain acreage owned and operated by Oasis Petroleum in Wild Basin. Specifically, Mirada asserts that Oasis Petroleum has breached certain agreements by: (1) failing to allow Mirada to participate in Oasis Petroleum’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that OPNA be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; that certain agreements apply to Oasis Petroleum and Mirada and Wild Basin with respect to this dispute; that Oasis Petroleum be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and that OPNA not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to Oasis Petroleum’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in Oasis Petroleum’s Wild Basin midstream operations, consisting of produced and flowback water disposal, crude oil gathering and gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of Oasis Petroleum’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”
On June 30, 2017, Mirada amended its original petition to add a claim that Oasis Petroleum has breached certain agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for midstream services provided by OPNA or its affiliates.
On February 2, 2018 and February 16, 2018, Mirada filed a second and third amended petition, respectively. In these filings, Mirada alleged new legal theories for being entitled to enforce the underlying contracts, and added Bighorn DevCo LLC, Bobcat DevCo LLC and Beartooth DevCo LLC as defendants, asserting that these entities were created in bad faith in an effort to avoid contractual obligations owed to Mirada. Mirada may further amend its petition from time to time to assert additional claims as well as defendants.
On March 2, 2018, Mirada filed a fourth amended petition that described Mirada’s alleged ownership and assignment of interests in assets purportedly governed by agreements at issue in the lawsuit. On August 31, 2018, Mirada filed a fifth amended petition that added the Partnership as a defendant, asserting that it was created in bad faith in an effort to avoid contractual obligations owed to Mirada.
Oasis Petroleum believes that Mirada’s claims are without merit, that Oasis Petroleum has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements which do not apply to Oasis Petroleum. Oasis Petroleum filed answers denying all of Mirada’s claims and intends to continue to vigorously defend against Mirada’s claims. Discovery is ongoing, and each of the parties has made a number of procedural filings and motions, and additional filings and motions can be expected over the course of the claim. Trial is scheduled for February 2020. Neither we nor Oasis Petroleum can predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to our or Oasis Petroleum’s interests, or if we or Oasis Petroleum were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on our business, results of operations, financial condition and cash flows. Such an adverse determination could materially impact Oasis Petroleum’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on its current development schedule. A determination that Mirada has a right to participate in Oasis Petroleum’s midstream operations could materially reduce the interests of Oasis Petroleum and us in our current assets and future midstream opportunities and related revenues in Wild Basin. Under the Omnibus Agreement the Partnership entered into with Oasis Petroleum in connection with the closing of the initial public offering, Oasis Petroleum agreed to indemnify the Partnership for any losses resulting from this litigation. However, the

32


Partnership cannot guarantee that such indemnity will fully protect the Partnership from the adverse consequences of any adverse ruling.
Item 1A. — Risk Factors
Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.
For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our 2018 Annual Report. There have been no material changes in our risk factors from those described in our 2018 Annual Report and subsequent SEC filings.


33


Item 5. — Other Information
On May 6, 2019, the Partnership entered into an amendment to its Revolving Credit Facility to (i) increase the aggregate amount of commitments from $400.0 million to $475.0 million ; (ii) provide for the ability to further increase commitments to $675.0 million ; and (iii) add a new lender to the bank group.



34


Item 6. — Exhibits
Exhibit
No.
 
Description of Exhibit
 
 
 
 
Second Amended and Restated Limited Liability Company Agreement of Bobcat DevCo LLC, dated as of February 22, 2019, by and between OMP Operating LLC, as the managing member, and Oasis Midstream Services LLC, as a member (incorporated herein by reference to Exhibit 10.1 to the Form 8-K filed by the Partnership on February 28, 2019).
 
 
 
 
Second Amended and Restated Limited Liability Company Agreement of Beartooth DevCo LLC, dated as of February 22, 2019, by and between OMP Operating LLC, as the managing member, and Oasis Midstream Services LLC, as a member (incorporated herein by reference to Exhibit 10.2 to the Form 8-K filed by the Partnership on February 28, 2019).
 
 
 
 
Second Amendment to Credit Agreement, dated as of May 6, 2019 among Oasis Midstream Partners LP, as Parent, OMP Operating LLC, as Borrower, the Other Credit Parties party thereto, Wells Fargo Bank, N.A., as Administrative Agent and the Lenders thereto.
 
 
 
 
Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
 
 
 
 
Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
 
 
 
 
Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
 
 
 
 
Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
 
 
 
101.INS(a)
 
XBRL Instance Document.
 
 
101.SCH(a)
 
XBRL Schema Document.
 
 
101.CAL(a)
 
XBRL Calculation Linkbase Document.
 
 
101.DEF(a)
 
XBRL Definition Linkbase Document.
 
 
101.LAB(a)
 
XBRL Labels Linkbase Document.
 
 
101.PRE(a)
 
XBRL Presentation Linkbase Document.
___________________
(a)     Filed herewith.
(b)     Furnished herewith.



35


SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OASIS MIDSTREAM PARTNERS LP
 
 
 
 
 
By: OMP GP LLC, its general partner
Date:
May 8, 2019
 
By:
 
/s/ Taylor L. Reid
 
 
 
 
 
 
 
Taylor L. Reid
 
 
 
 
 
 
 
Chief Executive Officer and Director
(Principal Executive Officer)
 
 
 
By:
 
/s/ Richard N. Robuck
 
 
 
 
 
 
 
Richard N. Robuck
 
 
 
 
 
 
 
Senior Vice President and Chief Financial Officer
(Principal Accounting Officer and Principal Financial Officer)


36
Oasis Midstream Partners (NASDAQ:OMP)
Historical Stock Chart
From Feb 2024 to Mar 2024 Click Here for more Oasis Midstream Partners Charts.
Oasis Midstream Partners (NASDAQ:OMP)
Historical Stock Chart
From Mar 2023 to Mar 2024 Click Here for more Oasis Midstream Partners Charts.